Sour gas is natural gas or any other hydrocarbon gas containing significant amounts of hydrogen sulfide (H2S). These gases, because of the rotten egg smell provided by its sulfur content, is commonly called “sour gas.” Typically, the sulfur that exists in a sour gas stream can be extracted and marketed on its own. In fact, according to the U.S. Geological Survey, U.S. sulfur production from gas processing plants accounts for about 15 percent of the total U.S. production of sulfur. Natural gas is usually considered sour if there are more than 5.7 milligrams of H2S per cubic meter of natural gas, which is equivalent to approximately 4 ppm by volume. On the other hand, natural gas that does not contain significant amounts of hydrogen sulfide is called “sweet gas.” In contrast, acid gas is any gas that contains significant amounts of acidic gases such as carbon dioxide (CO2) or hydrogen sulfide.
Before a raw natural gas containing hydrogen sulfide and/or carbon dioxide can be used, the raw gas must be treated to remove those impurities to acceptable levels. This treatment to remove hydrogen sulfide is referred to as a sweetening process. The removed hydrogen sulfide is most often subsequently converted to by-product elemental sulfur in a Claus process or it can be treated in a WSA Process unit where the by-product is sulfuric acid.
Treatment of sour gas to remove hydrogen sulfide is important because the presence of sour gas is usually undesirable in fuel streams because sulfur compounds can be extremely harmful, even lethal, to breathe. Moreover, sour gas can be extremely corrosive. Therefore, gas processing is an instrumental piece of the natural gas value chain. It is instrumental in ensuring that the natural gas intended for use is as clean and pure as possible, making it the clean burning and environmentally sound energy choice.
Challenges encountered in treating sour gas include a high variability in the concentration of sour gas components, such as hydrogen sulfide, carbon dioxide, various hydrocarbons, and other components. Sour gas streams especially rich in hydrogen sulfide concentrations on the order of at least about 15%, at least about 20%, and higher are especially challenging to treat in terms of the process equipment required to achieve the desired hydrogen sulfide removal. Unless otherwise noted, all percentages in this specification are based on a mole percent or a volume percent basis.
A variety of conventional treatment methods exist for removal of hydrogen sulfide from sour gas. By far, the most common conventional method for treating sour gas to remove the hydrogen sulfide is by an amine gas treating process. Other conventional methods of sour gas treatment include limited cryogenic fractionation processes.
The amine process, alternatively known as the Girdler process, is used in about 95 percent of U.S. gas sweetening operations. In this process, the sour gas is run through a tower, which contains the amine solution. This solution has an affinity for hydrogen sulfide, and absorbs it much like glycol absorbing water. Although a number of amine solvents may be used, two principle amine solutions used include monoethanolamine (MEA) and diethanolamine (DEA). Either of these compounds, in aqueous solution, will absorb sulfur compounds from natural gas as it passes through. The effluent gas is virtually free of sulfur compounds, and thus loses its sour gas status. The amine solution used can be regenerated (that is, the absorbed sulfur is removed), allowing it to be reused to treat more sour gas.
Unfortunately, conventional amine plants for the recovery of hydrogen sulfide suffer from a number of disadvantages. First, hydrogen sulfide amine separation plants are typically extremely energy intensive processes requiring significant amounts of energy to effect the required separations. Generally, higher H2S concentrations in sour gas require higher amounts of energy. This high energy requirement is undesirable both in terms of the resources required and cost considerations. Consequently, conventional amine treatment processes become much less desirable as the H2S content of sour gas increases.
Additionally, the carbon dioxide stream that is produced by an amine plant is typically produced at pressures close to ambient pressure. Consequently, sequestration of the carbon dioxide becomes problematic, because substantially elevated pressures are required to sequester carbon dioxide. Accordingly, sequestration of carbon dioxide from an amine plant requires additional costly equipment to compress the carbon dioxide to allow it to be captured, held, or subsequently used.
In addition to the problems of high energy usage and the challenges of carbon dioxide sequestration, amine treatment processes are also problematic with regards to solvent treatment. Because amine plants reuse their absorption solvents, the solvents must be regenerated by removing the absorbed sulfur compounds. This solvent regeneration in turn requires significant additional equipment, resulting in increased costs.
Moreover, amine plants are ill-suited for some environments such as the arctic cold. Because amine plants require certain elevated temperatures, additional heaters would be required to maintain the target operating temperatures of the process equipment if the plant were operated in such a cold region.
Furthermore, while amine plants remove sulfur compounds from sour gas, they fail to separate any carbon dioxide present in the sour gas. Thus, any carbon dioxide present in sour gas simply passes through an amine plant, staying with the produced hydrogen sulfide stream. Accordingly, any sulfur plant downstream of an amine plant must be sized to handle the additional throughput required by the presence of the carbon dioxide in the sulfur plant feed stream. Although some carbon dioxide can be tolerated in sweet gas streams, the increase in equipment size to handle the presence of the additional carbon dioxide can, in some cases, be quite substantial, resulting in undesirable equipment costs.
In addition to the common amine treatment processes, conventional cryogenic methods have been attempted to remove hydrogen sulfide from sour gas. Unfortunately, conventional cryogenic methods suffer from a number of disadvantages. For example, conventional cryogenic methods often suffer from the problem of solid formation in the cryogenic process equipment, resulting in plugged equipment and separation inefficiencies.
Moreover, conventional cryogenic methods suffer from separation difficulties due to the presence of various azeotropes. An azeotrope is a mixture of two or more liquids in such a ratio that its composition cannot be changed by simple distillation. This inability to separate components by distillation occurs because, when an azeotrope is boiled, the resulting vapor has the same ratio of constituents as the original mixture.
One example of an azeotrope that complicates the treatment of sour gas is the carbon dioxide/ethane azeotrope. Although highly desirable, the separation of carbon dioxide from ethane by distillation has proven to be a difficult problem in practice. This difficulty is caused by the fact that carbon dioxide and ethane form an azeotrope of approximately two thirds carbon dioxide and one third ethane on a mole basis. For a feed mixture containing ethane and carbon dioxide, this azeotrope tends to form in the upper portion of the column, usually making further separation beyond the azeotrope composition impossible. The common practice of employing two distillation towers operating at different pressures to work around the azeotrope does not help with the carbon dioxide/ethane system, because pressure has only a minimal effect on the composition of the azeotrope. Because of this insensitivity to pressure, attempts to separate carbon dioxide from ethane by distillation have heretofore resulted in an overhead carbon dioxide stream containing approximately azeotropic amounts of ethane, which are unacceptable in many applications.
Another example of an azeotrope complicating the treatment of sour gas is the ethylene/carbon dioxide azeotrope. Additionally, it is known that the acid gas hydrogen sulfide forms azeotropes with both ethane and propane. These and other possible azeotropes between acid gases and light hydrocarbons present limitations similar to those described for the carbon dioxide/ethane system when efforts are made to perform distillative separations on such systems.
Accordingly, there is a need in the art for improved processes for the treatment of sour gas that address one or more disadvantages of the prior art.